The present invention relates to a novel catalyst for use a method of reducing pollutant gas levels in flue gases generated in catalyst regenerators in hydrocarbon catalytic cracking systems.
Modern hydrocarbon catalytic cracking systems use a moving bed or fluidized bed of a particulate catalyst. Catalytic cracking is carried out in the absence of externally supplied molecular hydrogen, and is thereby distinguished from hydrocracking in which hydrogen is added. In catalytic cracking, the catalyst is subjected to a continuous cyclic cracking reaction and catalyst regeneration procedure. In a fluidized catalytic cracking (FCC) system, a stream of hydrocarbon feed is contacted with fluidized catalyst particles in a hydrocarbon cracking zone, or reactor, usually at a temperature of about 800.degree.-1100.degree. F. (427.degree.-600.degree. C.) to yield gasoline and light distillates. The reactions of hydrocarbons at this temperature result in deposition of carbonaceous coke on the catalyst particles. A substantial portion of the sulfur in the cracking feed stock deposits along with the coke on the catalyst. The resulting fluid products are thereafter separated from the coked catalyst and are withdrawn from the cracking zone. The coked catalyst is stripped of volatiles, usually with steam, and is cycled to a catalyst regeneration zone. In the catalyst regenerator, the coked catalyst is contacted with a gas, such as air, which contains a predetermined concentration of molecular oxygen to burn off the coke from the catalyst, consequently heating the catalyst to a high temperature. After regeneration, the hot catalyst is cycled to the cracking zone, where it is used to vaporize the hydrocarbons and to catalyze hydrocarbon cracking. The flue gas formed by combustion of coke in the catalyst regenerator, which contains SO.sub.x and NO.sub.x, is removed from the regenerator. Currently, the flue gas may be treated to remove particulates and carbon monoxide, after which the treated gas is normally passed into the atmosphere. Concern with the emission of pollutants in flue gas, such as sulfur oxides, has resulted in a search for improved methods for controlling such pollutants.
The hydrocarbon feeds processed in commercial FCC units normally contain sulfur, usually termed "feed sulfur". It has been found that about 2-10% or more of the sulfur in a hydrocarbon feedstream processed in an FCC system is invariably transferred from the feed to the catalyst particles as a part of the coke formed on the catalyst particles during cracking. The sulfur deposited on the catalyst, herein termed "coke sulfur", is passed from the cracking zone on the coked catalyst into the catalyst regenerator. Thus, about 2-10% or more of the feed sulfur is continuously passed from the cracking zone into the catalyst regeneration zone on the coked catalyst. In an FCC catalyst regenerator, sulfur contained in the coke is burned, forming gaseous sulfur dioxide and sulfur trioxide, which are emitted from the regenerator in the flue gas.
Most of the feed sulfur does not become coke sulfur in the cracking reactor. Instead, it is converted either to normally gaseous sulfur compounds such as hydrogen sulfide and carbon oxysulfide, or to normally liquid organic sulfur compounds. All these sulfur compounds are carried along with the vapor cracked hydrocarbon products recovered from the cracking reactor. Thus, about 90% or more of the feed sulfur is continuously removed from the cracking reactor in the stream of processed, cracked hydrocarbons, with about 40-60% of this sulfur being in the form of hydrogen sulfide. Provisions are conventionally made to recover hydrogen sulfide from the effluent from the cracking reactor. Typically, a very-low-molecular-weight off-gas vapor stream is separated from the C.sub.3 + liquid hydrocarbons in a gas recovery unit, and the off-gas is treated, as by scrubbing with an amine solution, to remove the hydrogen sulfide. Removal of sulfur compounds such a hydrogen sulfide from the fluid effluent from an FCC cracking reactor, e.g., by amine scrubbing, is relatively simple and inexpensive, relative to removal of sulfur oxides from an FCC regenerator flue gas by conventional methods. Moreover, if all the sulfur which must be removed from streams in an FCC operation could be recovered in a single operation performed on the reactor off-gas, the use of plural sulfur recovery operations in an FCC unit could be obviated, reducing expense.
It has been suggested to reduce the amount of sulfur oxides in FCC regenerator flue gas by desulfurizing a hydrocarbon feed in a separate desulfurization unit prior to cracking or to desulfurize the regenerator flue gas itself, by a conventional flue gas desulfurization procedure, after its removal from the FCC regenerator. Clearly, either of the foregoing alternatives requires an elaborate, extraneous processing operation and entails large capital and utilities expenses.
If sulfur normally removed from the FCC unit as sulfur oxides in the regenerator flue gas is instead converted to H.sub.2 S and removed along with the processed cracked hydrocarbons, the sulfur thus shifted from the regenerator flue gas to the reactor effluent constitutes simply a small increment to the large amount of hydrogen sulfide and organic sulfur invariably present in the reactor effluent. The small added expense, if any, of removing even as much as 5-15% more hydrogen sulfide from an FCC reactor off-gas by available means is substantially less than the expense of reducing the flue gas sulfur oxides level by separate feed desulfurization. Present commercial facilities for removing hydrogen sulfide from reactor off-gas can, in most if not all cases, handle any additional hydrogen sulfide which would be added to the off-gas if the sulfur normally discharged in the regenerator flue gas were substantially all shifted to form hydrogen sulfide in the FCC reactor off-gas. It is accordingly desirable to direct substantially all feed sulfur into the fluid cracked products removal pathway from the cracking reactor and thereby reduce the amount of sulfur oxides in the regenerator flue gas.